Tubing Pipe Centralizer

ABSTRACT

Embodiments of the invention generally provide a tube centralizer. The tube centralizer generally includes a base structure, and at least one rubber fin formed on the base structure, wherein the at least one rubber fin is configured to separate an inner pipe to which the tube centralizer is attached from an outer pipe.

BACKGROUND

The present disclosure generally relates to pipes for extracting oil and gas from a well, and more specifically to pipe centralizer devices for positioning a pipe within a well.

Petrochemical products such as oil and gas are ubiquitous in society and can be found in everything from gasoline to children's toys. Because of this, the demand for oil and gas remains high. In order to meet this high demand, it is important to locate oil and gas reserves in the Earth and extract them. Scientists and engineers conduct surveys utilizing, among other things, seismic and other wave exploration techniques to find oil and gas reservoirs within the Earth, and then extract those reserves by drilling wells into the Earth.

During the drilling of an oil or gas well, a drill string pipe is conventionally employed carrying a drill bit or other cutting tool at its lower operative end. Such pipe strings can eventually have a very considerable length which can sometimes exceed 9000 meters. It is uncommon, for a number of reasons, for a pipe string to be of strictly rectilinear configuration and it is, in fact, common practice deliberately to drill a bore hole of gently curved configuration so that a number of such bore holes can be produced from a single drilling platform with their lowermost ends spread over a considerable area around that single platform. Whether straight or gently curved, it is conventional practice to line the wall of a bore hole with steel piping as the length of that bore hole progressively increases. This steel piping is generally known as a bore hole casing. A pipe string commonly referred to as “tubing” partially fills this casing, and initially carries the drill bit or other cutting tool and subsequently carries therethrough the oil or gas from the well. The tubing frequently contacts the surrounding bore hole casing inevitably causing frictional wear of the metallic drill string itself and similar wear or other damage to the surrounding casing.

The bore hole casing has several functions. A primary function is to isolate successive geological levels and corresponding soil and rock formations from one another so far as the interior of the bore hole is concerned. Thus, the casing prevents fluids in its interior from reaching its exterior and vice versa except, of course, at the level or levels from which oil or gas is to be obtained.

The oil or gas is usually, although not always, under very high natural pressure and the ability of the bore hole casing to resist this pressure depends upon the thickness and integrity of the casing and the strength of the steel from which it is formed. It will immediately be realized that any portion of the casing which is subject to this high pressure and that is worn thin by frictional contact with the tubing pipe will eventually rupture if the frictional wear continues. A consequent shut-down of the drilling operation will then be necessary with lengthy and expensive remedial work being required before the casing is restored to a fully effective condition.

Frequently, the length of productive life of a well is determined substantially wholly by the duration of the integrity of its bore hole casing. It has been the practice, for a considerable period of time, to try and eliminate, or at least reduce, the frictional wear that has been discussed above.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings.

It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 illustrates an exemplary oil well installation according to an embodiment of the invention.

FIG. 2 illustrates an exemplary tubing pipe centralizer according to an embodiment of the invention.

FIG. 3 illustrates yet another view of a tubing pipe centralizer of FIG. 2, according to an embodiment of the invention.

FIG. 4 illustrates another exemplary embodiment of the tubing pipe centralizer.

FIGS. 5A-D illustrate exemplary shapes of fins according to embodiments of the invention.

FIG. 6 is a flow diagram of exemplary operations to manufacture a centralizer, according to an embodiment of the invention.

DETAILED DESCRIPTION

In the following, reference is made to embodiments of the invention. However, it should be understood that the invention is not limited to specific described embodiments. Instead, any combination of the following features and elements, whether related to different embodiments or not, is contemplated to implement and practice the invention. Furthermore, in various embodiments the invention provides numerous advantages over the prior art. However, although embodiments of the invention may achieve advantages over other possible solutions and/or over the prior art, whether or not a particular advantage is achieved by a given embodiment is not limiting of the invention. Thus, the following aspects, features, embodiments and advantages are merely illustrative and are not considered elements or limitations of the appended claims except where explicitly recited in a claim(s). Likewise, reference to “the invention” shall not be construed as a generalization of any inventive subject matter disclosed herein and shall not be considered to be an element or limitation of the appended claims except where explicitly recited in a claim(s).

FIG. 1 illustrates an oil well installation 100 according to an embodiment of the invention. As shown, the well 100 may extend from a surface 110 to an oil bearing formation 116 below the surface 110. The surface 110, for illustrative purposes is shown as an on shore surface. However, a person skilled in the art will appreciate that embodiments of the invention may also be suitably adapted for an offshore installation. Regardless of the type of well, in general, the well 100 may include several piping structures that extend below the earth, which, at their upper end form a well head 112. The well head 112 may include valves and other components for receiving oil from the oil bearing formation 116.

The well 100 may generally be defined by a well bore casing pipe structure or structures (hereinafter referred to simply as “casing”) 114. As described above, the casing pipe structure may separate successive geological levels and corresponding soil and rock formations from one another and an interior region of the well that may be used to transport the oil to the well head. In other words, the casing prevents fluids from the interior region of the well from reaching its exterior, and vice versa. Within the oil bearing region 116, however, the casing pipe may include perforations 118 to receive oil for transport to the surface.

A tubing pipe structure (hereinafter referred to simply as tubing) 120 may be used to transport oil received via the perforations 118 of the casing 114 in the oil bearing formation 116 to the well head 112. As shown in FIG. 1, the tubing 120 may extend from the oil bearing formation region 116 to the well head 112, and may be open at the end 122 to receive the oil entering from the casing 114. In one embodiment, a pump 130 may be inserted in the tubing 120 to facilitate the extraction of oil. The pump 130 may include a pump piston that is operated by a sucker rod system 132 extending through the well head and driven by a conventional pump drive (not shown). Extracted oil at the upper end of the tubing 120 may be transferred through appropriate piping and valves 124 to a treater 126 for storage within tank 128.

The tubing and casing pipes may have any desirable length, diameter, wall thickness, and the like. For example, in one particular embodiment, the tubing pipe or casing pipe diameter may be defined per API 5CT N80 and API 5CT L80.

As described above, the length of productive life of the well 100 may depend substantially on the duration of the integrity of its bore hole casing 114. Accordingly, the casing 114 may be coated with a suitable material to prevent rusting and other chemical processes which may eat into the pipe and create faults. Furthermore, to prevent damage to the casing during insertion of the tubing 120, one or more centralizers 150 may be coupled to the tubing 120. The centralizers 150 may have an annular shape and may be attached to the tubing 120 at predefined intervals such that the tubing 120 remains centered, or at a desired position or distance within the casing 114 and prevent friction therebetween.

Prior art centralizers are typically made from a metallic material which may scrape through the protective coating on the inner surface of the casing 114. This type of damage may expose the casing pipe to rusting that may eventually lead to a failure in the casing pipe. When failures occur, the casing pipe may have to be replaced, which may prove to be expensive and time consuming, and may introduce an unacceptable delay in well production. Embodiments of the invention provide a novel centralizer device that reduces damage to the inner walls of the casing pipe, thereby extending the productive life of the well and reducing interruptions for expensive repair work.

FIGS. 2 and 3 illustrate an exemplary centralizer 200 according to an embodiment of the invention. As shown the centralizer 200 may have an annular shape to match the shape of a tubing pipe 220. In alternative embodiments, the centralizer 200 may have any other shape that allows the centralizer to be affixed or otherwise clamped on to the tubing pipe 220 at a desired location and maintain the tubing pipe in a desired configuration with respect to the casing pipe 214.

In one embodiment, the centralizer 200 may include a base structure 201 and a plurality of fins 202 formed thereon. The base structure 201 may, in one embodiment, be made of a metallic material or a metallic alloy, for example iron, steel, carbon steel, or the like. In one embodiment, the base structure 201 may be bonded to the tubing pipe at a desired location using a suitable bonding agent. The fins 202 may be made of a rubber material, for example, Nitrile Rubber, SBR, Butyl, Neoprene, Ethylene Propylene Copolymer, HNBR, Natural Rubber Isoprene, Polyacrylate, Silicone, or the like. While four fins 202 are shown in FIG. 3, in alternative embodiments, any number of fins may be formed on the sleeve 201.

FIG. 4 illustrates an alternative embodiment of the invention. As shown, a centralizer 400 may be coupled to adjoining ends of two tubing pipe sections 410 and 420 using tubing couplers 411 and 421, respectively. As with the centralizer 200 of FIGS. 2 and 3, the centralizer 400 may also include a base structure 401 and a plurality of fins 402. The base structure 401, in one embodiment, may have a tubular shape, and may be configured to facilitate transfer of a drill string, oil, gas, and other materials that may be transported within the tubing pipe sections 410 and 420. Like the base structure 201, the base structure 401 may also be made of a metallic material, for example, iron, steel, carbon steel, or the like.

The couplers 411 and 421 may also be metallic tubular sections that may, in one embodiment, include threading configured to couple with threading formed on ends of the tubing pipe sections 410, 420, and the base structure 401. In alternative embodiments, any other reasonable means of coupling, for example, clamping, may be used by the couplers to couple the tubing pipe sections 410 and 420 to the base structure 401. In yet another embodiment, the couplers 411 and 421 may be omitted, and the base structure 401 may be configured to directly couple to the pipe sections 410 and 420 via, for example, male/female threading formed thereon.

In one embodiment of the invention, the fins of a centralizer (e.g., the fins 202 and 402) may have a hydrodynamic shape. The fin 202 illustrated in FIG. 2 is one example of such a hydrodynamically shaped fin. A hydrodynamically shaped fin may allow fluids to pass around the fin without collecting on top of or on any surface of the fin. By providing a hydrodynamically shaped fin, embodiments of the invention may permit fluids, mud, and other substances to be transferred efficiently in the space between a tubing pipe and a casing pipe for various reasons.

Embodiments of the invention are not limited to hydrodynamically shaped fins or any particular hydrodynamic shape for the fin. In alternative embodiments, the fins may not have a hydrodynamic shape. FIGS. 5A-D illustrate several alternative shapes for the fins 202 and/or 402. In general embodiments of the invention are not limited by the specific shape of the fin. Rather, any rubber material fin, having any shape, formed on a metallic base structure which also may have any reasonable shape capable of coupling to a tubing pipe, fall within the purview of the invention.

FIG. 6 is a flow diagram illustrating an exemplary process for manufacturing a centralizer according to an embodiment of the invention. As shown, the process may begin in step 610 by providing a base structure on which the fins are to be formed. The base structure may be, in one embodiment, a metallic sleeve having a predefined diameter. In step 620, an outer surface of the base structure may be sand blasted to create a clean and rough surface. In step 630, the outer surface of base structure may be coated with a primer material. Exemplary primer materials include Chemlok 205, in one embodiment. After the primer material has had sufficient time to cure, in step 640, a bonding agent may be applied to the outer surface of the base structure. Exemplary bonding agents may include Chemlok 253X, in one embodiment. Thereafter, in step 650, a rubber material may be molded on to the outer surface using, for example, a hydraulic electric press to form one or more fins on the outer surface. Finally, in step 660, the fins may optionally be trimmed and/or polished.

By providing centralizers having rubber fins embodiments of the invention achieve several advantages over the prior art. For example, fins made of rubber and molded in particular shapes are unlikely to scratch or otherwise damage an inside surface of the casing wall. Therefore, embodiments of the invention significantly reduce the likelihood of having to halt production from a well to repair damage to casing walls caused by centralizers. Moreover, the rubber fins produce significantly less noise from abrasion or rattling from contact with the casing pipe. This reduced noise may improve measurements and fidelity of sensors used in logging while drilling (LWD), measuring while drilling (MWD), or other tools that may be employed to collect data inside the well.

Yet another embodiment of the invention is the reusability of the centralizer devices. In one embodiment, centralizers that are recovered from a well may be refurbished for further use. Refurbishment of the centralizers may involve cutting off entire or damaged portions of the fins, and forming new fins or restoring portions of the fins using one or more of the steps outlined in FIG. 6.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

What is claimed is:
 1. A tube centralizer, comprising a base structure; and at least one rubber fin formed on the base structure, wherein the at least one rubber fin is configured to separate an inner pipe to which the tube centralizer is attached from an outer pipe.
 2. The tube centralizer of claim 1, wherein the base structure is made of a metallic material.
 3. The tube centralizer of claim 1, wherein the rubber fin is made of nitrile rubber.
 4. The tube centralizer of claim 1, wherein the base structure is an annular sleeve configured to wrap around the inner pipe.
 5. The tube centralizer of claim 1, wherein the rubber fin comprises a substantially hydrodynamic profile.
 6. The tube centralizer of claim 1, wherein the inner pipe comprises at least a first segment and a second segment, wherein the centralizer couples with an end of the first segment and an end of the second segment, thereby coupling the first segment and the second segment.
 7. The tube centralizer of claim 6, wherein the centralizer couples with the end of the first segment via a first coupler and the end of the second segment via a second coupler.
 8. An oil well comprising: a casing pipe string; a tubing pipe string; and at least one centralizer attached to the tubing pipe string, comprising: a base structure; and at least one rubber fin formed on the base structure, wherein the at least one rubber fin is configured to separate the tubing pipe string from the casing pipe string.
 9. The oil well of claim 8, wherein the base structure is made of a metallic material.
 10. The oil well of claim 8, wherein the base structure is an annular sleeve configured to wrap around the inner pipe.
 11. The oil well of claim 8, wherein the rubber fin comprises a substantially hydrodynamic profile.
 12. The oil well of claim 8, wherein the tubing pipe string comprises at least a first segment and a second segment, wherein the centralizer couples with an end of the first segment and an end of the second segment, thereby coupling the first segment and the second segment.
 13. The oil well of claim 12, wherein the centralizer couples with the end of the first segment via a first coupler and the end of the second segment via a second coupler.
 14. The oil well of claim 8, wherein the rubber fin is made of nitrile rubber.
 15. A method for manufacturing a pipe centralizer, comprising: providing a base structure; sand blasting an outer surface of the base structure; coating the outer surface with a primer; applying a bonding agent to the outer surface; and molding at least one rubber fin on the outer surface.
 16. The method of claim 14, further comprising trimming and polishing the at least one rubber fin. 